Crude stabilizer process

ABSTRACT

Embodiments described herein provide a method and apparatus for stabilizing a product, such as a petroleum or other hydrocarbon based product, for example crude oil. Stabilization removes volatile components from the crude such that the crude product may be safely handled, stored, and/or transported. In one embodiment, the crude stabilization system includes at least a stabilizer column and an overhead system. Effluent from the stabilizer column may be fed directly into a suction inlet of a compressor system of the overhead system. The stabilizer column is preferably operated at low pressures and temperatures, thus making a desalting system unnecessary. Furthermore, overhead trim cooling, recycle cooling, and interstage cooling may be provided by the crude feed rather than air coolers or cooling water. As such, stabilized crude product may be safely transported via any means of transportation, such as a railcar.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit to U.S. Provisional Patent ApplicationNo. 62/248,203, filed Oct. 29, 2015, the entirety of which is herebyincorporated by reference.

BACKGROUND

Field

Embodiments of the present disclosure generally relate to a process andsystem for the stabilization of crude. More specifically, embodimentsdescribed herein relate to methods and apparatus for stabilizing crudeoil components which may be hazardous during handling, storage, and/ortransportation.

Description of the Related Art

A process for the stabilization of crude products generally consists ofbringing crude oil at a well outlet to API standards, whilesubstantially removing lighter hydrocarbons therefrom. Maximizing theproduction of crude oil which does not degas, limiting losses of lighthydrocarbons, and obtaining a stabilized crude product for safetransportation is highly desired. Although bulk separation of oil,water, and gas occurs in the field, the resulting liquid often retainshigh quantities of light ends, resulting in a high vapor pressure orRVP. For transportation, further stabilization (e.g., to a lower vaporpressure) may be required to remove soluble light hydrocarbons from thecrude.

Conventional small field stabilization units, often referred to as“heater treaters,” can be used to stabilize crude for transportation,but these units are inefficient. Conventional stabilization unitsutilize high amounts of energy to operate and fractionate poorly, asmore light material must be removed from the crude oil to meet the samevapor pressure specification. There is an incentive to minimize theamount of light material removed from the crude (i.e., minimize theshrinkage) because that material must then be sold at a discount.Minimizing shrinkage provides more stabilized crude oil available forsale at full crude price.

Conventional stabilizer columns are more efficient than field heatertreaters and operate at and/or maintain crude products therein atpressures of about 150 psig, top temperatures of about 250 degreesFahrenheit, and bottom temperatures of about 350 degrees Fahrenheit. Toprocess crude feeds containing salts, such high temperatures require theuse of a desalting system, as temperatures above about 350 degreesFahrenheit hydrolyze feed chlorides. Hydrolyzed feed chlorides formacids that corrode equipment.

Therefore, there is a need for an improved crude stabilization systemwhich maintains low process pressures and temperatures, reduces productshrinkage, and provides a stabilized crude product for safetransportation.

SUMMARY

Embodiments described herein provide a method and apparatus forstabilizing a product, such as a petroleum or other hydrocarbon basedproduct, for example crude oil. Stabilization removes volatilecomponents from the crude such that the crude product may be safelyhandled, stored, and/or transported. In one embodiment, the crudestabilization system includes at least a stabilizer column and anoverhead system. Effluent from the stabilizer column may be fed directlyinto a suction inlet of a compressor system of the overhead system. Thestabilizer column is preferably operated at low pressures andtemperatures, thus making a desalting system unnecessary. Furthermore,overhead trim cooling, recycle cooling, and interstage cooling may beprovided by the crude feed rather than air coolers or cooling water. Assuch, stabilized crude product may be safely transported via any meansof transportation, such as a railcar.

In one embodiment, a crude stabilization system is disclosed. The crudestabilization system includes a stabilizer column and an overheadsystem. The stabilizer column may include a first section, a secondsection, a third section, and a fourth section. The second section mayinclude at least one tray. The third section may include a plurality oftrays. The fourth section may include a reboiler. The third section maybe located between the second section and the fourth section. Theoverhead system may include a compressor. Furthermore, the first sectionmay be directly connected to the compressor of the overhead system.

In another embodiment, a crude stabilization system is disclosed. Thecrude stabilization system includes a feed system, a stabilizer column,an overhead system, a reboiler system, and a stabilized crude system.The feed system may include a heating unit and a filtering unit. Thestabilizer column may include a plurality of sections for processing thecrude. The stabilizer column may be operatively connected with the feedsystem. The overhead system may include a compressor. An exit nozzle ofthe stabilizer column may be directly connected with a suction inletnozzle of the compressor. The reboiler system is operatively connectedto the stabilizer column and may include a heater. The stabilized crudesystem may include a plurality of coolers. The stabilized crude systemmay be operatively connected with the stabilizer column.

In yet another embodiment, a method for stabilizing crude is disclosed.The method includes transferring the crude from a storage tank into afeed system, processing the crude within the feed system, andtransferring the crude from the feed system to a stabilizer column. Themethod may further include processing the crude through the stabilizercolumn, transferring a vapor of the crude from the stabilizer columndirectly to a compressor of an overhead system, and compressing thevapor of the crude within the overhead system at a first stage tobetween about 2 psig and about 80 psig. The method may also includecompressing the vapor of the crude within the overhead system at asecond stage to between about 100 psig and about 200 psig.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlyexemplary embodiments of this disclosure and are therefore not to beconsidered limiting of its scope, for the disclosure may be applied toother equally effective embodiments.

FIGS. 1A and 1B are schematics illustrating a crude stabilization systemand process flows, according to one embodiment.

FIG. 2 is a flow diagram illustrating operations of a method forstabilizing crude, according to one embodiment.

To facilitate understanding, identical reference numerals have beenused, where possible, to designate identical elements that are common tothe figures. It is contemplated that elements and features of oneembodiment may be beneficially incorporated in other embodiments withoutfurther recitation.

DETAILED DESCRIPTION

Embodiments described herein provide a method and apparatus forstabilizing a product, such as a petroleum or other hydrocarbon basedproduct, for example crude oil. Stabilization removes volatilecomponents from the crude such that the crude product may be safelyhandled, stored, and/or transported. In one embodiment, the crudestabilization system includes at least a stabilizer column and anoverhead system. Effluent from the stabilizer column may be fed directlyinto a suction inlet of a compressor system of the overhead system byprocess piping. The stabilizer column is preferably operated at lowpressures and temperatures, thus making a desalting system unnecessary.Furthermore, overhead trim cooling, recycle cooling, and interstagecooling may be provided by the crude feed rather than air coolers orcooling water. As such, stabilized crude product may be safelytransported via any means of transportation, such as a railcar.

FIGS. 1A and 1B are schematics illustrating a crude stabilization system100 and process flows for separating various components of the crude.The crude stabilization system 100 preferably includes a feed system200, a stabilizer column 300, an overhead system 400, a reboiler system500, and a stabilized crude product system 600. The crude stabilizationsystem 100 may separate and/or remove volatile components from thecrude. The resulting crude product may be safely handled, stored, and/ortransported. Safe transport of the stabilized crude product may beprovided by a pipeline, a railcar 102, or a tanker located at or nearthe location of the crude stabilization system 100.

The feed system 200 processes the crude by pumping the crude via a pump202 from a storage tank 204 into the crude stabilization system 100 viasupply lines 206. In some embodiments, the pump 202 may be a unit chargepump. In certain embodiments, the crude pumped by the feed system 200may be raw, cold crude. The raw, cold crude may provide trim cooling toa tower overhead material, for example, a liquefied petroleum gas (LPG)product, via a heat exchanger 218 (See, FIG. 1B). The temperature of theLPG product may determine the amount of crude that passes through theheat exchanger 218 and the amount of crude that bypasses around the heatexchanger 218 via line 351 which may be controlled by a flow controlvalve 352. The raw, cold crude may also be heated via a feed-bottomsexchanger 208 of the feed system 200. In certain embodiments, the crudemay be heated in a feed-bottoms exchanger. The crude may be heated to atemperature between about 70 degrees Fahrenheit and about 135 degreesFahrenheit, for example about 90 degrees Fahrenheit. The feed-bottomsexchanger 208 may be operatively connected with a temperature controller240 to control a temperature of the stabilized crude product 608.Heating the crude may warm the crude and reduce the viscosity of thecrude.

In some embodiments, condensate feed may be pumped from a tank farm 280by pump 282 via supply line 284. Supply line 284 may merge with supplyline 206. The flow of the condensate feed may be controlled by a flowcontrol valve 288. Flow control valve 288 may be operatively connectedand/or controlled by flow controller 286.

The warmed crude may pass through a filter 210 to remove solids and/ordebris therefrom. The filter 210 may prevent the accumulation of solidsin the stabilizer column 300 and/or in the reboiler system 500. Thefilter 210 prevents the solids from passing into the stabilizer column300 and/or the reboiler system 500. The filter 210 may remove particleslarger than about 90 microns, thus preventing sediment build-up in thestabilizer column 300. Downstream of filter 210, the filtered crude maybe split into a first portion, which is diverted into a slipstream line212, and second portion which is diverted into a filtered crude line211. A pipe 209 may be located between the filter 210 and a flow controlvalve 216. The slipstream line 212 may join the pipe 209 upstream of theflow control valve 216, for example between the flow control valve 216and the filter 210. The pipe 209 may be coupled with the filtered crudeline 211 and may deliver filtered crude to the filtered crude line 211.The flow control valve 216 restricts flow to divert the first portion ofthe filtered crude into the slipstream line 212. The flow control valve216 may be controlled to open and/or close via a flow signal 222 from aflow controller 224. The first portion of the filtered crude may includebetween about five percent and about fifty percent, for example aboutfifteen percent, of the filtered crude. The second portion of thefiltered crude may include the remainder of the filtered crude notincluded in the first portion of the filtered crude. In someembodiments, the slipstream line 212 may deliver the first portion ofthe filtered crude to a compressor area 214. In the compressor area 214,the filtered crude may provide interstage and/or recycle cooling of thecompressed overhead vapor.

Compressor area 214 may compress and condense overhead from thestabilizer column 300, some of which becomes liquid LPG product storedin storage location 418, discussed infra, and some of which may berecycled back in reflux supply line 420. The second portion of thefiltered crude passes through the flow control valve 216. In someembodiments, the flow control valve 216 may be a feed flow controlvalve. Downstream of the flow control valve 216, the first portion ofthe filtered crude and the second portion of the filtered crude may berejoined and the total filtered crude feed may be transferred to thestabilizer column 300 via filtered crude line 211 which may carryfiltered, warmed crude. The filtered, warm crude exits an outlet nozzleof the feed system and enters an inlet nozzle of the stabilizer column300. The filtered crude line 211 may optionally have a temperaturecontroller 215 operatively connected thereto for monitoring atemperature of the filtered warm crude. The slipstream line 212 maytransfer filtered crude to the overhead system 400 (See, FIG. 1B) viaoverhead line 230. Overhead line 230 may divert a first portion of thefiltered crude through the overhead system 400 via overhead line 230Asuch that the first portion of filtered crude is heat integrated withthe compressed overhead material. Overhead line 230A may absorb heatfrom various compressed streams from compressor 214, described infra.Overhead line 230B may also divert filtered crude from overhead line 230and may absorb heat from the compressor recycle line 273, and then maybe recombined with filtered crude in filtered crude line 211.

Before entering the stabilizer column, an LPG reflux stream 420 mayoptionally mix with the filtered crude line 211. The flow of the LPGreflux stream 420 may be controlled by a flow control valve 229. Flowcontrol valve 229 may be operatively connected and/or controlled by flowcontroller 231.

The stabilizer column 300 may include a first section 310, a secondsection 320, a third section 330, and a fourth section 340. It iscontemplated that the stabilizer column may include any number ofadditional sections, as needed. The stabilizer column 300 separates thefiltered crude and/or removes lighter hydrocarbons from the filteredcrude.

The first section 310 may be a top section located above the inletnozzle of the stabilizer column 300 and upstream of the second section320. The inlet nozzle may be a crude feed distributor. The first section310 may be a compressor knockout drum. The first section 310 may beoperatively connected to a compressor 402 (See FIG. 1B). The compressor402 may compress vapor from the first section 310. In some embodiments,the first section 310 may be part of the stabilizer column 300. Allvapors from the first section 310 may be charged to the suction of thecompressor 402. In some embodiments, all compressor suction vapor mayflow through the first section 310. Vapor from the compressor knockoutdrum of the first section 310 may, in some embodiments, be transferredvia a vapor line 440 to a flare 442. Flow of vapor to the flare in thevapor line 440 may be controlled by a controller 444 and a control valve446 operatively connected to the vapor line 440. Liquid from thecompressor knockout drum, along with liquids condensed and recycled inthe overhead system 400 (described in more detail below in connectionwith FIG. 1B), settle to the bottom of the first section 310 by gravityand flow to the second section 320. Gravity may force the crude andother liquids to settle out onto a chimney tray. The chimney tray mayhave a sump therein.

The second section 320 is located below the first section 310. Thesecond section 320 may process the liquid of the filtered crude suchthat the second section 320 removes water from the liquid of thefiltered crude. The second section 320 may further prevent wateraccumulation within the stabilizer column 300. The second section 320may include at least one tray 323. It is contemplated, however, that thesecond section 320 may include any number of trays 323 for processingthe filtered crude. The second section 320 may include a water drawtray. In some embodiments, the second section 320 may comprise aplurality of trays above the water draw tray. Vapor rising past the atleast one tray 323 may heat filtered crude before an accumulator tray322 to a temperature between about 100 degrees Fahrenheit and about 140degrees Fahrenheit, for example a temperature of about 120 degreesFahrenheit. In some embodiments, accumulator tray 322 may be acollector. The heating may be accomplished via heat transfer between arising vapor and a falling liquid in the stabilizer column 300. Theheating may warm the crude on the accumulator tray 322 to allow easierremoval of water from the filtered crude on the accumulator tray 322.The water may be drawn from the accumulator tray 322 to the separatordrum 326 via a water removal line 213. Hydrocarbon liquid productremaining after the water removal on the accumulator tray 322 may flowto the third section 330, for example by overflowing a weir into adowncomer.

Liquid filtered crude from accumulator tray 322 may be transferred to aseparator drum 326. In some embodiments, separator drum 326 may be ahorizontal separator drum. The separator drum 326 may separate water andhydrocarbon from the filtered crude. A mixed stream of water and crudemay be drawn from the stabilizer column 300 to a separator drum 326.From separator drum 326, the water may be pumped out of the separatordrum 326 and the excess crude (that was drawn with the water) may bereturned to the stabilizer column 300. Advantages of the separator drum326 include removing water from the crude and preventing water fromdescending farther down the stabilizer column 300. Furthermore, bydrawing a high flow-rate in excess of the expected water rate and thenseparating and returning the crude back to the stabilizer column 300,any solids such as dirt, rust, and scale, may be removed and/or maysettle out in the horizontal separator drum 326. Such solids maysubsequently be pumped out of the separator column 300, thus preventingthe fouling and plugging of trays.

The separated water may be pumped out of the crude stabilization system100 via water line 370. Water in the water line 370 may be pumped bypump 328 to a disposal tank 368 or other suitable location. The pump 328may be operatively connected to level controller 372. Level controller372 may control separator drum 326. Level probe 373 may produce a levelsignal input to the controller 372. The controller 372 may operatecontrol valve 374 to adjust the flow of water out of the separator drum326 such that the interface between water and hydrocarbon is controlledin the separator drum 326, thus preventing hydrocarbon from going towater disposal tank 368. The separated hydrocarbons may be recycled tothe second section 320 via recycle line 350. The flow and/or amount ofseparated hydrocarbons transferred by recycle line 350 may be controlledby flow control valve 274. Flow control valve 274 may be operativelyconnected and/or controlled by flow controller 272, which may target aflow rate for the control valve 274 based on a material balance aroundthe separator drum 326, including total flow into the separator drum 326and water flow out through valve 374.

Liquid from the second section 320 is transferred to the third section330. Vapor from the second section 320 is transferred to the firstsection 310, as discussed supra. In some embodiments, the liquid mayexit the second section 320 via an outlet nozzle and enter the thirdsection 330 via an inlet nozzle. The third section 330 includes aplurality of trays 332. In certain embodiments, the plurality of trays332 may include between about four trays 332 and about thirty trays 332,for example about ten trays 332. The plurality of trays 332 may receiverecycled hydrocarbon from separator drum 326. At least one tray of theplurality of trays 332 may include a weir and a downcomer. In someembodiments the tray may include at least one hole for liquid to fallthrough and risers or chimneys for vapor to rise through to moderatepressure of the vapor. The plurality of trays 332 may strip the overheadLPG product from the bottom stabilized crude product. The plurality oftrays 332 separate light hydrocarbons from heavier hydrocarbons to yielda stabilized crude product that is ultimately withdrawn as tower bottomsand an LPG product that is ultimately recovered from tower overheadsystem. Heat and mass is transferred between the descending liquidmaterial and rising vapor generated by the reboiler system 500. In someembodiments, the third section 330 may include a temperature controller334 for controlling a temperature of the third section 330. Liquids aretransferred from the third section 330 to the fourth section 340 by, forexample, weir and downcomer, holes, seal pans, and or risers.

The fourth section 340 may be below the third section 330. As such,liquid from the third section 330 may be transferred from the thirdsection 330 to the fourth section 340. In some embodiments, the crudemay exit the third section 330 via an outlet nozzle and enter the fourthsection 340 via an inlet nozzle. The fourth section 340 may include areboiler system 500. The reboiler system 500 may include a reboiler 342.In some embodiments, the reboiler 342 may be a heater. In certainembodiments, the heater of the reboiler system 500 may be a direct-firedheater or hot oil system. In some embodiments the reboiler 342 may be afurnace reboiler. The tower bottoms liquid may be pumped through heater342. The stabilizer column 300 is reboiled by the heater 342, andspecifically the crude containing heavy hydrocarbons is reboiled by theheater 342. A liquid rate may be set such that a temperature of a film(not shown) in the heater 342 remains lower than about 400 degreesFahrenheit, for example a temperature lower than about 350 degreesFahrenheit. Maintaining the film temperature in the heater 342 belowabout 350 degrees Fahrenheit may prevent hydrolysis of chlorides in thebottoms of the stabilizer column 300. Heating of the crude to atemperature greater than about 350 degrees Fahrenheit, for example about380 degrees Fahrenheit, may cause corrosion, which is conventionallyprevented by using a desalting system. Operating at the reducedtemperatures described herein reduces liberation of chlorides, and theresulting corrosion, so that a desalting system is not needed. Fuel gasmay be supplied to the reboiler 342 from a fuel gas storage tank 364, orpipeline, to the reboiler 342 via fuel gas line 360. Fuel gas line 360may be operatively connected to flow controller 362 for controlling theamount of fuel gas supplied to the reboiler 342. The fuel gas line 360may further be operatively connected to a process controller 366. Theprocess controller 366 may communicate with temperature controller 348in order to regulate the amount of fuel gas supplied to the reboiler 342such as to regulate the temperature of the reboiler. A partial baffle344 may force and/or direct the filtered crude into a flow pattern. Theflow pattern around partial baffle 344 may direct the filtered crude topass a bottom head 343 of the stabilizer column 300 and flow upward to areboiler draw nozzle. The flow pattern may function to remove sedimentand/or other unwanted materials out of the bottom head 343 rather thanpumping it to the reboiler system 500. In certain embodiments, thebottom head 343 may be a sump. The fourth section 340 may furtherinclude a temperature control 348 for measuring and maintaining atemperature of the reboiler return, a plurality of flow control valves352, and a plurality of flow controllers 354. Crude processed in thefourth section 340 may be pumped to the reboiler 342 in reboiler line217 via pump 345. Reboiled crude may be returned to the fourth section340 via reboiler return line 219.

The crude stabilization system 100 may further include an overheadsystem 400. Vapor exits an outlet nozzle of the stabilizer column 300and enters an inlet nozzle of the overhead system 400. Vapor may exitthe stabilizer column via overhead vapor line 270. The outlet nozzle ofthe stabilizer column 300 may be connected with the inlet nozzle of theoverhead system 400, such that the outlet nozzle of the stabilizercolumn 300 may be fed into the overhead system 400. The overhead system400 may include a compressor 402. The overhead system 400 may furthercomprise a plurality of flow indicators 412 for measuring flow of thevapor of the crude through the overhead system 400, and/or a pluralityof temperature controllers 414 for monitoring or regulating temperatureof the vapor of the crude. In certain embodiments, the compressor 402may be a two-stage compressor. In certain embodiments the compressor 402may be a two-stage dry screw compressor. It is contemplated that thecompressor 402 may be any suitable compressor, such as a one-stagecompressor, etc. The outlet nozzle of the stabilizer column 300 may bedirectly connected into an inlet of the compressor 402 by piping and/orvalves, without intervening equipment or other unit operations. As such,the vapor from the stabilizer column overhead may be directly fed intothe suction of the compressor 402. The vapor from the stabilizer columnmay be split between one or more compressors 402. A first stage 408 ofthe compressor 402 may compress the vapor to a pressure of between about2 psig and about 80 psig, for example between about 5 psig and about 50psig. Subsequent to the compressing of the vapor product at the firststage 408 of the compressor 402, interstage cooling is performed in aheat exchanger 434, such as a shell and tube exchanger. The interstagetemperature may be controlled above the vapor dew point. Subsequent tothe interstage cooling, the vapor product may enter the second stage 410of the compressor 402. Any condensibles may be separated in a knockoutdrum (not shown) prior to the second stage 410 and recycled to the firstsection 310 of the stabilizer column 300. In between the first stage 408and the second stage 410 of the compressor 402, interstage temperatureis controlled to a temperature above the crude vapor dew point to avoidfeeding large quantities of liquid to the second stage of the compressor402.

The second stage 410 of the compressor 402 may compress the vapor of thecrude to a pressure of between about 100 psig and about 200 psig, forexample about 150 psig. The vapor may exit the second stage 410 of thecompressor 402 at a pressure of about 150 psig. The vapor may becondensed, via condensers 406, 218, into a liquid LPG product, a ventgas product, and a water product. Condensers 406, 218 may liquefyoverhead from the stabilizer column 300, some of which becomes liquidLPG product stored in storage location 418, discussed infra, and some ofwhich is recycled back in reflux supply line 420. Each of the LPGproduct, the vent gas product, and the water product may be recovered ina high pressure receiver 416. The vent gas may be carried by vent gasline 430. Condensation may be performed using an air cooler 406. It iscontemplated, however, that although an air cooler 406 is disclosed,other coolers may be utilized within the embodiments disclosed. The aircooler 406 may be operatively connected to a temperature controller 450for regulating and/or monitoring a condensation rate of the air cooler406 by regulating and adjusting heat duty of the air cooler 406. Trimcooling may be provided by raw, cold crude, discussed supra withreference to the feed system 200. As such, trim cooling may be providedat heat exchanger 218. Two pressure control valves may regulate thepressure in the high pressure receiver 416. A differential pressurecontroller 404 may be upstream of air cooler 406. The differentialpressure controller 404 may create a pressure drop in the main stream toforce vapor through a hot vapor bypass 405. The pressure in the highpressure receiver 416 may be raised by opening the hot vapor bypass 405.The pressure in the high pressure receiver 416 may be lowered by ventingvapor to the fuel gas system.

If it is determined that compressor recycle of the vapor product isneeded, the recycle vapor product may be cooled against crude in a heatexchanger 436, such as shell and tube exchanger. Recycled vapor may beprovided back to the stabilizer column 300 via compressor recycle line273.

Liquid LPG product may be pumped to a storage location 418 via a pump424 in LPG supply line 432. In the event a vent gas is produced from thehigh pressure receiver 416, the gas may be mixed into the fuel gassystem and subsequently burned. Water may be returned to the stabilizercolumn 300 via water return supply line 422. The stabilizer column 300may capture the water in a horizontal water separator and combine thewater with the feed water. In some embodiments, the flow and/or amountof water transferred by water return supply line 422 may be controlledby a flow control valve (not shown). In certain embodiments, the flowcontrol valve may be operatively connected and/or controlled by a flowcontroller (not shown).

The crude stabilization system 100 may further include a stabilizedcrude system 600. Stabilized crude may be pumped, via pump 602, in acooled product stream 608 from a bottom head 606 of the stabilizercolumn 300 through a plurality of coolers 604. In some embodiments, theplurality of coolers 604 may be a plurality of air coolers. Theplurality of coolers 604 may reduce a temperature of the stabilizedcrude from about 160 degrees Fahrenheit to a temperature of less thanabout 140 degrees Fahrenheit, for example a temperature of about 120degrees Fahrenheit. The temperature of the stabilized crude may becontrolled and/or monitored by a temperature controller 612 operativelyconnected to the plurality of coolers 604. Subsequently, the stabilizedcrude may be transferred to the feed-bottoms exchanger 208. Within thefeed-bottoms exchanger 208 raw, cold crude in supply line 206 cools thestabilized crude in cooled product stream 608 to a temperature of lessthan about 110 degrees Fahrenheit, for example a temperature of about100 degrees Fahrenheit. In some embodiments, the cooled product streamline 608 may be operatively connected with a bypass line 610. Bypassline 610 may bypass the feed-bottoms exchanger 208. In some embodiments,the cooled product stream line 608 and/or the feed-bottoms exchanger 208may be operatively connected to a bypass control valve 611. The bypasscontrol valve 611 may control the stabilizer feed temperature tominimize overhead product. After cooling, the stabilized crude may betransferred, via cooled product stream 608, to a storage location (notshown) or may be loaded into a transport vehicle, such as a railcar 102.The flow of the stabilized crude may be controlled by a flow controller620 and a flow control valve 622.

FIG. 2 schematically illustrates operations of a method 700 for making astabilized crude product from a raw crude material according to oneembodiment described herein. In certain embodiments, the material may bea crude oil. At operation 710, the material may be transferred from astorage tank into a feed system. At operation 720 the material may beprocessed within the feed system. The processing of the material withinthe feed system may include heating the material to a temperaturebetween about 70 degrees Fahrenheit and about 110 degrees Fahrenheit,for example a temperature of about 90 degrees Fahrenheit. The processingof the material within the feed system may further include filtering thematerial. The processing of the material within the feed system may alsoinclude diverting a first portion of the material to a compressor areaand a second portion of the material to a flow control valve. Thecompressor area may accept interstage and recycle cooling from thematerial and preheat the feed to achieve heat recovery. The processingof the material within the feed system may also include rejoining thefirst portion of the material and the second portion of the material.

At operation 730 the material may be transferred from the feed system toa stabilizer column. At operation 740 the material may be processedthrough the stabilizer column. The processing of the material throughthe stabilizer column may include processing the material through astabilizer column with a first section, a second section, a thirdsection, and a fourth section. The first section of the stabilizercolumn may function as a compressor knockout drum. The second section ofthe stabilizer may remove water from the material and/or heat thematerial. The second section of the stabilizer column may heat thematerial to a temperature between about 100 degrees Fahrenheit and about140 degrees Fahrenheit, for example a temperature of about 120 degreesFahrenheit. Additionally, in some embodiments, the second section mayseparate water from the hydrocarbon, remove the water from thestabilizer column, and return to the stabilizer column any hydrocarbondrawn with the water stream. The third section of the stabilizer columnmay strip LPG products from the material. The fourth section of thestabilizer column may reboil the material.

At operation 750 a vapor of the material may be transferred from thestabilizer column directly to a compressor of an overhead system. Thetransferring may include transferring the vapor of the material directlyto a suction inlet nozzle of the compressor. In some embodiments, anexit nozzle of the stabilizer column may be directly connected with asuction inlet nozzle of the compressor by process piping and/or valves,without intervening equipment or other unit operations. At operation 760the vapor of the material may be compressed within the overhead systemat a first stage to between about 2 psig and about 80 psig. At operation770 the vapor of the material may be compressed within the overheadsystem at a second stage to a pressure between about 100 psig and about200 psig. The compressing may include using a two-stage dry screwcompressor to increase the pressure of the vapor of the material. Insome embodiments, the vapor of the material may be cooled within a firstsection of the overhead system after the compressing of the vapor of thematerial within the overhead system at the first stage, and/or condensedwithin a second section of the overhead system after compressing thevapor of the material within the overhead system at the second stage.The interstage cooling may control a temperature of the vapor of thematerial above a vapor dew point of the vapor material. The condensingmay be provided by an air cooler. The condensing may separate the vaporof the material into a liquid LPG product, a vent gas, and water. TheLPG product, the vent gas, and the water may be separated into a highpressure receiver.

Throughout the method 700 for making a stabilized crude product, thetemperature of the material is maintained at a temperature below about350 degrees Fahrenheit. Maintaining the temperature of the materialbelow about 350 degrees Fahrenheit may prevent hydrolysis of feedchlorides. Heating the material to a temperature above about 350 degreesFahrenheit may cause extensive corrosion unless a desalting system isincluded upstream of the stabilization column. The method 700 avoids therequirement of a desalting system.

In some embodiments, the method 700 for stabilizing the material mayfurther include reboiling the stabilizer column with a fired heater,wherein a liquid rate is set such that a temperature of the fired heateris maintained below about 350 degrees Fahrenheit.

In some embodiments, the method 700 for stabilizing the material mayfurther include pumping the material from the stabilizer column to aplurality of coolers, wherein the plurality of coolers reduce thetemperature of the material to a temperature of less than about 140degrees Fahrenheit, for example about 120 degrees Fahrenheit.

In some embodiments, the method 700 for stabilizing the material mayfurther include transferring the material to a feed bottoms exchanger,wherein the feed bottoms exchanger cools the material to a temperatureof less than about 110 degrees Fahrenheit, for example about 100 degreesFahrenheit.

In some embodiments, the method 700 for stabilizing the material mayfurther include transferring the material into a storage tank and/or atransport tank, such as a railcar.

The crude stabilization system 100 described herein provides for a lowReid vapor pressure (RVP), thus allowing for materials, such as crude,to be produced more efficiently and at lower costs. RVP is a measure ofthe volatility of the material, such as the crude product. RVP isdefined herein as the absolute vapor pressure exerted by a liquid at 100degrees Fahrenheit as determined by the test method ASTM-D-323. The testmethod applies to volatile crude oil and volatile nonviscous petroleumliquids. Specifically, the processed crude described herein may have aRVP suitable for safely transporting the crude by railcar.

Benefits of the disclosure include a stabilizer column that operates andmaintains the crude at a low pressure and a low temperature. Toillustrate, the stabilizer column described herein may operate and/ormaintain crude therein at a pressure of about 5 psig, as describedsupra. By way of further example, the stabilizer column described hereinmay operate and/or maintain crude therein at a top temperature of about90 degrees Fahrenheit and a bottom temperature of about 160 degreesFahrenheit. Further benefits include a stabilizer column overhead whichfeeds material coming off of the stabilizer column overhead directlyinto the overhead system, and the inlet of the overhead system is thesuction of the two-stage dry screw compressor. Additional benefits mayinclude overhead trim cooling, recycle cooling, and interstage coolingprovided by the feed system rather than by air coolers or cooling water.

Low process pressures allow for lower equipment design pressures, thusreducing production costs, maintenance costs, and/or operational costs.As such, piping of the 150 pound class, for example, may be utilizedthroughout the entire crude stabilization system upstream of thecompressor. Low process temperatures allow for lower designtemperatures, thus reducing production costs, maintenance costs, and/oroperational costs. Low process temperatures may further allow for crudeproducts with significant salt levels, for example Bakken, to beprocessed within the crude stabilization system disclosed without theuse of a desalter. Reductions in the amount and types of equipmentrequired may further reduce production costs, maintenance costs, and/oroperational costs. A low bottoms temperature reduces the use andoperation of the fired heater, and provides for a reduction in the arearequired in the feed-bottoms exchanger service.

The apparatus described herein can be built at lower cost thanconventional high pressure crude stabilization systems because the partslist for the apparatus is minimized. Additionally, design pressures arelower, further reducing production and operational costs. Operation atlow pressure enables processing at lower heat and cooling loads,resulting in lower operating expense than conventional systems. Loweringthe consumption of fuel gas and/or eliminating the need for coolingwater reduces costs and reduces the overall footprint of the crudestabilization system. Moreover, the present disclosure results in lowercrude shrinkage, since a higher volume of crude feed is recoveredcompared to conventional crude stabilization systems.

It will be appreciated to those skilled in the art that the precedingexamples are not limiting. It is intended that all permutations,enhancements, equivalents, and improvements thereto that are apparent tothose skilled in the art upon a reading of the specification and a studyof the drawings are included within the true spirit and scope of thepresent disclosure. It is therefore intended that the following appendedclaims include all such modifications, permutations, and equivalents asfall within the true spirit and scope of these teachings.

What is claimed is:
 1. A crude stabilization system, comprising: astabilizer column, comprising: a first section; a second section,comprising at least one tray, a third section comprising a plurality oftrays; and a fourth section comprising a reboiler, wherein the thirdsection is between the second section and the fourth section; and anoverhead system, comprising a compressor, wherein the first section isoperatively connected to the compressor.
 2. The crude stabilizationsystem of claim 1, wherein an outlet of the stabilizer column isdirectly connected with an inlet of the overhead system.
 3. The crudestabilization system of claim 2, wherein the outlet of the stabilizercolumn is fed directly into an inlet of the compressor of the overheadsystem.
 4. The crude stabilization system of claim 1, wherein the firstsection further comprises a compressor knock out drum.
 5. The crudestabilization system of claim 1, wherein the second section comprises awater removal system.
 6. The crude stabilization system of claim 1,wherein the second section further comprises a water draw tray.
 7. Thecrude stabilization system of claim 6, wherein the second sectioncomprises a plurality of trays above the water draw tray.
 8. The crudestabilization system of claim 1, wherein the third section comprisesbetween about seven and about thirty trays.
 9. The crude stabilizationsystem of claim 1, wherein an outlet of a feed system is operativelyconnected to an inlet of the stabilization column.
 10. The crudestabilization system of claim 9, wherein the feed system comprises asupply line, a heat exchanger, and a filter.
 11. The crude stabilizationsystem of claim 1, wherein the compressor of the overhead system is atwo-stage compressor
 12. The crude stabilization system of claim 11,wherein the two-stage compressor is a two-stage dry screw compressor.13. The crude stabilization system of claim 11, wherein the first stageof the two-stage compressor compresses the crude to a first pressure,and wherein the second stage of the two-stage compressor compresses thecrude to a second pressure, wherein the second pressure is greater thanthe first pressure.
 14. The crude stabilization system of claim 13,further comprising a cooling unit between the first stage and the secondstage of the two-stage compressor.
 15. A crude stabilization system,comprising: a feed system, comprising: a heating unit; and a filteringunit; a stabilizer column, comprising a plurality of sections forprocessing the crude, wherein the stabilizer column is operativelyconnected with the feed system; an overhead system comprising acompressor, wherein an exit nozzle of the stabilizer column is directlyconnected with a suction inlet nozzle of the compressor; a reboilersystem operatively connected with the stabilizer column, the reboilersystem comprising a heater; and a stabilized crude system operativelyconnected with the stabilizer column, the stabilized crude systemcomprising a plurality of coolers.
 16. The crude stabilization system ofclaim 15, wherein the compressor is a two-stage dry screw compressor.17. The crude stabilization system of claim 15, wherein a first sectionof the stabilizer column comprises a compressor knock out drum.
 18. Thecrude stabilization system of claim 15, wherein a second section of thestabilizer column is a water removal system.
 19. The crude stabilizationsystem of claim 15, wherein a third section of the stabilizer columncomprises between about seven and about thirty trays.
 20. The crudestabilization system of claim 16, further comprising a cooling unitbetween the first stage and the second stage of the two-stage dry screwcompressor.
 21. The crude stabilization system of claim 15, wherein theheater of the reboiler system is a direct-fired heater or hot oilsystem.
 22. A method for stabilizing crude, comprising: transferring thecrude from a storage tank into a feed system; processing the crudewithin the feed system; transferring the crude from the feed system to astabilizer column; processing the crude through the stabilizer column;transferring a vapor of the crude from the stabilizer column directly toa compressor of an overhead system; compressing the vapor of the crudewithin the overhead system at a first stage to a pressure between about2 psig and about 80 psig; and compressing the vapor of the crude withinthe overhead system at a second stage to a pressure between about 100psig and about 200 psig.
 23. The method of claim 22, wherein theprocessing of the crude within the feed system comprises: heating thecrude to a temperature between about 70 degrees Fahrenheit and about 135degrees Fahrenheit; filtering the crude; diverting a first portion ofthe crude to a compressor area and a second portion of the crude to aflow control valve; and rejoining the first portion of the crude and thesecond portion of the crude.
 24. The method of claim 23, wherein thecrude provides interstage and recycle cooling of compressed vapors ofthe crude in the overhead system.
 25. The method of claim 22, whereinthe processing of the crude within the stabilizer column comprises:processing a vapor of the crude through a first section of thestabilizer column, wherein the first section of the stabilizer columncomprises a compressor knockout drum; processing the crude through asecond section of the stabilizer column, wherein the second sectionremoves water from the crude; processing the crude through a thirdsection of the stabilizer column, wherein the third section separatesLPG products from the crude; and processing the crude through a fourthsection of the stabilizer column, wherein the fourth section reboils thecrude.
 26. The method of claim 25, wherein the second section heats thecrude to a temperature between about 100 degrees Fahrenheit and about140 degrees Fahrenheit.
 27. The method of claim 25, wherein the secondsection further draws the water and the crude to a separator drum,wherein the separator drum removes the water from the crude andrecombines the crude with the stabilizer column.
 28. The method of claim25, wherein the first section is connected to the second section, thesecond section is connected to the third section, and the third sectionis connected to the fourth section.
 29. The method of claim 22, whereincompressing comprises using a two-stage dry screw compressor to increasethe pressure of the vapor of the crude.
 30. The method of claim 29,wherein transferring the crude from the stabilizer column directly tothe compressor of the overhead system further comprises transferring thevapor of the crude directly to a suction inlet of the two-stage dryscrew compressor.
 31. The method of claim 22, further comprising:cooling the vapor of the crude within a first section of the overheardsystem after the compressing of the vapor of the crude within theoverhead system at the first stage; and condensing the vapor of thecrude within a second section of the overhead system after compressingof the vapor of the crude within the overhead system at the secondstage.
 32. The method of claim 31, wherein the cooling controls atemperature of the vapor of the crude above a vapor dew point of thevapor of the crude.
 33. The method of claim 31, wherein the vapor of thecrude is condensed to form a liquid LPG product, a vent gas, and water.34. The method of claim 33, wherein the LPG product, the vent gas, andthe water are separated in a high pressure receiver.
 35. The method ofclaim 31, wherein the condensing is provided by an air cooler.
 36. Themethod of claim 22, further comprising reboiling a first area of thestabilizer column with a fired heater, wherein a liquid rate is set suchthat an outlet temperature of the fired heater is maintained betweenabout 250 degrees Fahrenheit and about 350 degrees Fahrenheit.
 37. Themethod of claim 36, further comprising pumping the crude from thestabilizer column to a plurality of coolers, wherein the plurality ofcoolers reduce the temperature of the crude to a temperature of lessthan about 140 degrees Fahrenheit.
 38. The method of claim 37, furthercomprising transferring the crude to a feed bottoms exchanger, whereinthe feed bottoms exchanger trim cools the crude to a temperature of lessthan about 110 degrees Fahrenheit.
 39. The method of claim 38, furthercomprising transferring the crude to a rail car.
 40. The method of claim22, wherein a temperature of the crude is maintained below about 350degrees Fahrenheit.
 41. The method of claim 31, wherein the condensingis provided by a heat exchange with the crude.